Claus feed gas hydrocarbon removal

ABSTRACT

A process for adsorbing hydrocarbons from an acid gas stream includes passing the acid gas stream through an adsorbent which selectively removes hydrocarbons, desorbing the hydrocarbons from the adsorbent and contacting the desorbed hydrocarbons with an acid gas removal solution to remove acid gases which have been coadsorbed with the hydrocarbons. The process is particularly useful in removing hydrocarbons from a hydrogen sulfide-containing stream which is being directed to Claus processing for conversion into elemental sulfur. Useful adsorbents include crystalline titanium silicate molecular sieves containing titania octahedral sites such as ETS-10 and similar materials, as well as high silica aluminosilicate zeolite.

FIELD OF THE INVENTION

[0001] This invention relates to a novel integrated process for removinghydrocarbon and other organic contamination from feed gas streams forClaus reactors. This invention also relates to the use of uniqueinorganic molecular sieves of the type containing octahedrallycoordinated metal sites, such as coordinated octahedrally titanium, inprocesses for removing hydrocarbon and other organic contamination fromhydrogen sulfide-containing streams.

BACKGROUND OF THE INVENTION

[0002] Natural gas as well as refinery gas streams are commonlycontaminated with sulfur compounds, especially hydrogen sulfide (H₂S).If substantial amounts of hydrogen sulfide are present, regulatoryrestrictions dictate special precautions must be taken to purify the gasstreams. In non-polluted areas, generally a maximum of two tons per dayof sulfur are allowed to be vented as sulfur oxide (SO₂) flare-off gasper processing plant. In populated areas even more stringentrestrictions are applied.

[0003] The first step in H₂S removal from natural gas and/or refinerystreams is accomplished by an acid gas removal unit. This unit removessubstantial amounts of H₂S and CO₂ from the processing stream. Theoff-gas of this stream contains predominantly CO₂ and H₂S. The sulfurfrom this off-gas stream is removed by the Claus reaction which producessalable elemental sulfur. The remaining CO₂ may be safely vented to theatmosphere.

[0004] The Claus process was discovered over 115 years ago and has beenemployed by the natural gas and refinery industries to recover elementalsulfur from hydrogen sulfide-containing gas streams for the past 50years. Briefly, the Claus process for producing elemental sulfurcomprises two major sections. The first section is a thermal sectionwhere H₂S is converted to elemental sulfur at approximately 1,800-2,200°F. No catalyst is present in the thermal section. The second section isa catalytic section where elemental sulfur is produced at temperaturesbetween 400-650° F. over an alumina catalyst. The reaction to produceelemental sulfur is an equilibrium reaction, hence, there are severalstages in the Claus process where separations are made in an effort toenhance the overall conversion of H₂S to elemental sulfur. Each stageinvolves heating, reacting, cooling and separation. A flow diagram ofthe Claus process is shown in FIG. 1 which will be explained in moredetail below.

[0005] In the thermal section of the conventional Claus plant, astoichiometric amount of air is added to the furnace to oxidizeapproximately one-third of the H₂S to SO₂ and also burn all thehydrocarbons and any ammonia (NH₃) present in the feed stream. Theprimary oxidation reaction is shown as follows:

2H₂S+3O₂→2SO₂+2H₂O  (1)

[0006] This reaction is highly exothermic and not limited byequilibrium. In the reaction furnace, the unconverted H₂S reacts withthe SO₂ to form elemental sulfur. This reaction is shown as follows:

2H₂S+SO₂⇄3S^(o)+2H₂O  (2)

[0007] Reaction (2) is endothermic and is limited by equilibrium.

[0008] In the catalytic section of the Claus process, the unconvertedhydrogen sulfide and sulfur dioxide from the thermal stage are convertedto sulfur by the Claus reaction (2) over an alumina catalyst. Typically,there are three stages of catalytic conversions. Important features ofthe Claus reaction in the catalytic stage are that the reaction isequilibrium limited and that the equilibrium to elemental sulfur isfavored at lower temperatures.

[0009] The Claus process was modified in 1938 by I. G. Fabenindustrieand various schemes of the modified process are utilized today. For feedgas streams containing approximately 40% H₂S, the balance carbon dioxide(CO₂) and water (H₂O), the once through Claus process is generallyemployed in which all of the acid gas is fed directly to the burner.Three catalytic stages are typically utilized after the initial thermalstage. This scheme will generally produce an overall recovery of 95-97%sulfur. If this recovery efficiency is acceptable, no further processingis required. However, if the recovery efficiency is not high enough (fora variety of reasons and, in particular, environmental constraints) anadvanced Claus process such as Comprimo's Super Claus process which hasa sulfur efficiency of 99.0% can be utilized. This process consists ofthe replacement of the final Claus reaction stage by, or the additionof, a reaction stage featuring a proprietary catalyst to promote thedirect oxidation of hydrogen sulfide to sulfur selectively in the Claustail-gas. Air is injected upstream of the reactor. The hydrogen sulfideand oxygen react over the catalyst via the following reaction:

2H₂S+O₂→2S^(o)+2H₂O  (3)

[0010] If a sulfur recovery efficiency of greater than 99% is required,a tail-gas cleanup unit (TGCU) needs to be employed. This type of unitallows for an overall sulfur recovery efficiency of 99.8%. In the UnitedStates, a sulfur recovery efficiency of 99.8+% is required for Clausproduction units generating greater than or equal to 50 STSD ofelemental sulfur, hence, a TGCU such as the Shell Scot process is oftenrequired. Such processes coupled with a sulfur recovery unit (SRU) canmeet and exceed a sulfur recovery efficiency of 99.8+%.

[0011] There are other modifications to the basic Claus process. Oneparticular modification to the Claus process that is widely used todayis the “Split-Flow” process for feed gas streams containing 30-35% H₂Sor less concentrations. In this scheme, 40-60% of the feed gas is passeddirectly to the catalytic section, bypassing the noncatalytic reactionfurnace. This process is utilized to achieve a hotter temperature and amore stable flame in the furnace. The bypassed feed joins the furnaceeffluent after the condenser and the combined flow enters the firstcatalytic converter. The sulfur recovery efficiency for this scheme isnormally 1-3% lower than the conventional once-through orstraight-through process. Basic descriptions of Claus process schemesand additional tail-gas cleanup units are given in the Kirk OthmerEncyclopedia of Chemical Technology, Vol. 23, pp. 440-446, the contentsof which are incorporated herein by reference.

[0012] In the Claus reaction scheme, it can be seen that combustion airis a critical variable in maintaining a high efficiency operation in thethermal section. Hydrocarbon impurities and other feed gas contaminantsnot only cause a high temperature operation (up to 2,500° F.) suchcontaminants cause problems in maintaining the correct amount ofcombustion air. Additionally, it should be noted that in the firstcatalytic stage, any carbonyl sulfide (COS) and carbon disulfide (CS₂)that are formed in the reaction furnace and/or any such materialsentering the catalytic section with the feed gas such as in the splitflow process must be hydrolyzed to hydrogen sulfide and CO₂ if they areto be removed. Any sulfur in the form of COS or CS₂ leaving the firstcatalytic stage cannot be recovered by the Claus process because of thelower temperatures used in the second and subsequent catalytic stages. Abottom bed temperature of 600-640° F. is required in the first catalyticstage for good hydrolysis which in turn requires an inlet bedtemperature greater than 500° C. Normal operation for the inlet bedtemperature is generally 450-460° F., hence the higher temperature forthe former does not favor the equilibrium to elemental sulfur formation.

[0013] In the Claus process design and operation to date, it is thedesign and operation of the reaction furnace, reaction furnace burnerand the first catalytic converter or stage which are critical in aneffort to achieve a successful operation. The burner is a critical pieceof equipment in that it must be able to burn one-third of the incomingH₂S while also burning all the impurities in the feed gas stream,namely, paraffin and aromatic hydrocarbons, ammonia and low molecularweight organics at substoichiometric air conditions. This is criticalnot only to the Claus unit where oxygen (O₂) is detrimental to thealumina catalysts but also to the tail-gas cleanup units where areducing condition is employed at the front end of the unit. In thedesign of the reaction furnace burner, there has been considerablediscussion as to the type of burner to be utilized based solely oneconomics. More complex and expensive burners can handle moderatelyhigher concentrations of hydrocarbon impurities and even highermolecular weight hydrocarbons, up to 1% propane. However, burner design,no matter how expensive, only addresses coping with the impurity and notsolving the problem. In fact, the burner does not combust the lighterhydrocarbons, but the combustion products are mostly CS₂ and CO₂ andthese compounds create additional problems that must be addressed. Also,when hydrocarbons are combusted, additional air is fed and CO₂ and H₂Oare generated which adds to the volumetric flow which in turn requireslarger equipment for a given sulfur production rate. Another problem isthe fact that even the most expensive burner design cannot handle C₄+aliphatic hydrocarbons and all aromatic hydrocarbons. These materialscan generate soot or polymeric hydrocarbons which can coat the reactionfurnace and the first catalytic converter catalyst.

[0014] There are other problems associated with the presence ofhydrocarbons in the Claus feed stream and consequent generation of CS₂.The reaction of the hydrocarbons with H₂S and O₂ are endothermic in afurnace where an exothermic condition is required to generate asufficient high temperature for their destruction. Additionally, in thefirst catalytic converter, any CS₂ that is not hydrolyzed goes throughthe remaining part of the Claus unit as CS₂ and presents a loss insulfur recovery efficiency and a potential explosive hazard. As a casein point, the addition of 2% light hydrocarbon as methane (CH₄) andethane (C₂H₆) and 1.5% C₆+ in the Claus feed results in a capitalincrease for the Claus plant of approximately 33%. Additionally, andalso very important, the emissions as SO₂ and CO₂ increase by 25%.

[0015] It can be seen that hydrocarbon and other organic contaminationof feed gas streams for Claus reactors, common in natural gaspurification as well as in oil refinery processing, cause substantialprocessing problems. In addition to deactivating the Claus catalyst,organic species, when combined with sulfur, form a wide range ofundesirable compounds. Many of these compounds are toxic and subject tostrict regulatory restrictions. These regulations are driving efforts toidentify appropriate means to remove the hydrocarbon and other organiccontaminants before they reach the Claus reactor.

[0016] Adsorptive solutions to this hydrocarbon and organiccontamination problem currently center on the use of activated carbons.However, the inability of activated carbons to completely reversiblyregenerate results in excessive adsorbent consumption. After only a fewcycles, the carbon must be disposed of and replaced because it rapidlyloses adsorption capacity with each regeneration.

[0017] It would be very advantageous if an adsorbent could be identifiedwhich removed organic and other hydrocarbon contaminants from the highlypolar acid gas stream which constitutes the Claus reactor feed. It wouldbe especially advantageous if this adsorbent could be regenerated andreused through many cycles without substantial loss of adsorptioncapacity.

[0018] Adsorbents may be broken into two broad groups; those with alarge quantity of specific, highly charged sites and those with largenon-specific uncharged surfaces. Zeolites would represent a primeexample of a “specific” adsorbent and carbon and silica would representprime examples of the “nonspecific” types. Specific site adsorbents maybind species very strongly, allowing for the essentially completeremoval of favored trace components from larger streams. The sites insuch materials bind with polar or polarizable species by electrostaticinteraction. The bulk of Claus gas feed streams consist of highly polarH₂O and H₂S and extremely polarizable CO₂. However, the sites in thespecific adsorbent materials may be overwhelmed by the polar andpolarizable species in such a stream and essentially a reduced number ofsites would be available for binding with organics and hydrocarbons.Non-specific adsorbents tend to bind physically larger molecules ontheir surfaces and thus would be expected to selectively adsorb largerhydrocarbons from the combination of small molecules (H₂O, H₂S, CO₂)which form the bulk of Claus feed streams. However, the weak bindingenergy inherent to non-specific adsorbents such as carbon substantiallylimits the adsorption capacity, especially of small hydrocarbons such aspropane. Moreover, as discussed above, the non-specific adsorbents donot readily regenerate to the full original adsorbent capacity, and mustbe replaced after only a few adsorption/regeneration cycles.

[0019] It would be desirable to remove a broad spectrum of hydrocarbonsin a Claus feed gas pretreatment system. An appropriate adsorbent wouldbe a material which behaves like a non-specific adsorbent in the senseof favoring larger species such as organic and hydrocarbons whilebinding these with the high interaction forces and high selectivitiesassociated with specific cited materials.

[0020] Importantly, it has been found that regardless of the adsorbentused, there is a level of H₂S which is coadsorbed with the hydrocarbons.Without further processing, the adsorbed H₂S would be present in thedesorbed stream upon regeneration of the absorbent. This desorbed streamcannot be vented to the atmosphere or vented to a fuel system because ofthe residual H₂S content. Further, co adsorption of H₂S diminishesadsorbent activity for hydrocarbon removal resulting in the need foradditional adsorbent requirement and consumption. Accordingly, the coadsorption of H₂S represents an inherent problem in practicing theremoval of hydrocarbons from a Claus feed stream using adsorptionprocessing.

SUMMARY OF THE INVENTION

[0021] It has now been found that the unique three-dimensional frameworkof “EXS” molecular sieves, are particularly effective for the removal oforganic compounds including hydrocarbons from hydrogensulfide-containing feed gas streams for Claus reactors. EXS molecularsieves are distinguished from other molecular sieves by possessingoctahedrally coordinated active sites in the crystalline structure.These molecular sieves contain electrostatically charged units that areradically different from charged units in conventional tetrahedrallycoordinated molecular sieves such as in the classic zeolites. Members ofEXS family of sieves include, by way of example, ETS-4 (U.S. Pat. No.4,938,939), ETS-10 (U.S. Pat. No. 4,853,202) and ETAS-10 (U.S. Pat. No.5,244,650), all of which are titanium silicates or titanium aluminumsilicates. The disclosures of each of the listed patents areincorporated herein by reference. The EXS sieves exhibit isotherms attemperatures slightly above ambient indicating the more active bindingof organic species whereas at these temperatures, polar species showonly minimal adsorption. As a consequence, organic species such asaliphatic and aromatic hydrocarbons can be selectively adsorbed frompolar streams such as the feed gas stream to Claus reactors whichcontain polar species of H₂S, CO₂ and water.

[0022] Unlike the use of activated carbons, the organic species whichhave been adsorbed by the molecular sieves used in this invention can beremoved by thermal or pressure swing processes reversibly for manycycles without significant loss of adsorption capacity. Accordingly, thepresent invention is further directed to a specific process of using,regenerating and reusing EXS molecular sieves for adsorbing organicspecies from hydrogen sulfide-containing or other polar gas streams.

[0023] The invention is also directed to a novel integrated process forremoving hydrocarbons from a Claus feed stream using adsorptionprocessing. In general, this invention effectively solves the problem ofH₂S coadsorption and the consequent process inefficiencies andenvironmental problems which result. The inherent problem of H₂Scoadsorption is solved in this invention by contacting the desorbedstream obtained from regeneration of the adsorbent with a lean acid gasremoval solution either as an aqueous amine or physical solvent. Theamine solution or solvent separates the residual H₂S from the desorbedhydrocarbons. The newly rich solution containing polar gases can berecycled to natural gas or refinery stream clean-up processing. In thisintegrated process it has been found that the EXS molecular sieves andhigh silica aluminosilicate zeolites are useful adsorbents for removingthe hydrocarbons from the Claus feed.

BRIEF DESCRIPTION OF THE DRAWINGS

[0024]FIG. 1 is a schematic of the Claus process which shows both thestraight-through and split-flow processing schemes.

[0025]FIG. 2 presents the adsorption isotherms of various compounds onhydrogen exchanged ETS-10 at various pressures.

[0026]FIG. 3 is a schematic of a processing scheme for adsorbing organiccompounds from a hydrogen sulfide-containing Claus feed gas integratedwith the process for removal of H₂S from natural gas.

DETAILED DESCRIPTION OF THE INVENTION

[0027] This invention is particularly directed to the treatment of ahydrogen sulfide-containing feed gas stream to a Claus plant. In theprocess of this invention, the feed gas stream to a Claus plant istreated so as to remove hydrocarbon and other organic contaminationtherefrom. Hydrogen sulfide-containing streams are advantageouslytreated in the Claus plant to convert the hydrogen sulfide to sulfur. Aschematic of a typical three-stage Claus plant is shown in FIG. 1. Thefirst step of the Claus process involves a controlled combustion of afeed gas which contains hydrogen sulfide and the noncatalytic reactionof unburned hydrogen sulfide with sulfur dioxide as depicted inreactions (1) and (2) above. In the straight through process, a feed gascontaining hydrogen sulfide is directed via line 10 to reaction furnace12 which contains a burner 14 where the feed gas is combusted. Oxygen issupplied to burner 14 by an air stream via line 16. From the reactionfurnace 12, the products are cooled in a waste heat boiler 18 and theproducts condensed and separated in condenser 20 into a liquid sulfurstream 22 and gaseous product stream. Gaseous products are reheated vialine 24 in reheater 26 and passed through a series of catalytic reactors28, 30 and 32 wherein the unreacted hydrogen sulfide and sulfur dioxidereact over a catalyst, typically alumina, to produce sulfur and water asdepicted in reaction (2). Subsequent to each reaction, the reactionproducts are condensed in respective condensers 29, 31 and 33 whereinliquid sulfur is separated and removed via respective lines 23, 25 and27 and joined with liquid sulfur from line 22 to form a final sulfurstream 35. Precedent to the respective catalytic reactions in reactors30 and 32, the product gas directed from the preceding condensers 29 and31 is reheated in respective reheaters 34 and 36 which receive thecooled gas stream via lines 37 and 39, respectively. Tail gas leavingcondenser 33 via line 40 can be treated in the conventional ways,including burning or further treatment to recover additional sulfur aswas previously described and well-known in the art.

[0028] An alternative to the strait-through process, is the split-flowprocess. In this process, 40-60% of the Claus feed bypasses the burnerand is fed directly to the first catalytic stage. This process is shownin FIG. 1 wherein line 42 directs a portion of the H₂S-containing feedfrom line 10 into line 24 containing product gas from condenser 20. Themixed stream is heated in reheater 26 and passed to first stagecatalytic reactor 28.

[0029] The present invention is concerned with treating theH₂S-containing feed gas stream 10 directed either to burner 14 or bypassline 42. In addition to the hydrogen sulfide, feed stream 10 containscarbon dioxide and typically about 3 weight percent hydrocarbons, aswell as small amounts of water. The heavy aliphatic and aromatichydrocarbon constituents of this feed stream present particularlyserious problems in operating the Claus process. In addition to rapiddeactivation of the Claus reactor catalyst, a portion of these organiccompounds form toxic species with sulfur. These compounds are subject toadditional regulatory control. While burner design has been improved tohandle moderately higher concentrations of hydrocarbon impurities, andeven higher molecular weight hydrocarbons, the burner design, no matterhow intricate or expensive, only addresses coping with the organicimpurities and not solving the problem.

[0030] In accordance with the present invention, an improved process isprovided using adsorbents to remove the organic contaminants from thehydrogen sulfide-containing feed gas stream to a Claus plant. Theimproved process solves a problem which has adversely affected adsorbentprocesses in the past, that being the co adsorption of H₂S and theconsequent economic inefficiencies and, more importantly, the occurrenceof additional environmental problems as discussed previously. Theadsorbents useful in this invention need to bind hydrocarbons morestrongly than other constituents of the Claus feed gas stream includingH₂S, CO₂, and H₂O. Examples of useful adsorbents include high silicazeolites such as zeolite beta, zeolite Y and ZSM-5 and derivativesthereof and, non-polar amorphorous adsorbents including silica and likederivatives. The term “high silica” refers to zeolites having aSiO₂/Al₂O₃ mole ratio of at least 4 and, preferably, at least 5. Aparticularly useful high silica zeolite is HiSiv™ 1000, a zeolite Y fromUOP. Particularly useful are the EXS molecular sieves which areconstructed from units of octahedral titania chains strung together bytetrahedral silica webs. This construction is radically different fromclassical molecular sieves such as zeolites and induces radicallydifferent adsorption properties. In particular, the EXS molecular sievesdemonstrate unusual adsorption properties toward polar species. Whilesubstantial adsorption of all species is seen at ambient temperature,modest temperature rises collapse the adsorption isotherms of the polarspecies. The EXS adsorbents are essentially non-adsorptive toward waterat temperatures approaching 100 EC. Carbon dioxide demonstratesadsorptive properties on these adsorbents much like water, wherein theadsorption isotherm collapses rapidly at rising temperatures. Hydrogensulfide, being a polar species, would reasonably be expected to behavelike water and carbon dioxide. In fact, the present inventors have shownthat indeed, the adsorption properties of the EXS adsorbents behave withrespect to hydrogen sulfide similarly to the adsorptive behavior ofpolar species water and carbon dioxide. Conversely, organic species suchas C₁-C₈ aliphatics and aromatics bind very strongly to the EXSadsorbents. Much higher temperatures are needed to desorb thesehydrocarbon species.

[0031] In accordance with one aspect of the present invention, a feedstream containing a combination of polar species including H₂S, CO₂ andwater and organics, including hydrocarbons, is passed through an EXSadsorbent at a temperature of approximately 50-100 EC. The polar speciesare eluted with a minium of adsorption while the hydrocarbons and otherorganics are substantially adsorbed and retained within the EXSadsorbent. Thus, the organic contaminants in a Claus plant feed streamare essentially removed. As a consequence, simplified burner and furnacedesign can be used, reducing equipment costs. Moreover, downstream tailgas treatment can be drastically reduced since the toxic species whichform by the reaction of the organics and the hydrogen sulfide aredrastically reduced. Elevating the temperature of the adsorbent afterpassage of the feed stream, such as to a temperature above 200° C.desorbs the organics and regenerates the adsorbent for the nextadsorption cycle at reduced temperatures.

[0032] Members of the EXS family of sieves which can be used in thepractice of this invention include ETS-4, ETS-10 and ETAS-10, all ofwhich have been described in the art and patented. The respective patentnumbers for each adsorbent have been set forth above. The most preferredadsorbent for use in this invention is ETS-10. ETS-10 is stable tohundreds of degrees above the appropriate desorption temperature and,accordingly, remains useful through repeated adsorption/desorptioncycles with minimal loss of adsorption capacity. Active sites on themolecular sieves can be exchanged with various cations as is known inthe art including, for example, hydrogen, sodium and calcium cations.

[0033] EXS sieves used in the presence of this invention may be employedin any useful physical form. This includes fine powders, shapedparticles such as fluidizable microspheres, pellets, honeycombs, or incomposites supported on substrates.

[0034] This invention can be carried out by employing variousadsorption/desorption cycles such as thermal swing cycles, pressureswing cycles, as well as the use of another fluid or gas to desorb theorganics, or combinations of the above. Regardless of the adsorbentused, it is important to both minimize and recover H₂S which has beencoadsorbed along with the organic, including hydrocarbon, constituentsof the Claus feed gas.

[0035] A particular adsorption/desorption cycle is shown in FIG. 3 inwhich a multiple bed thermal swing adsportion (TSA) unit is utilizedalong with a purge gas such as methane to remove organics from a Clausplant feed stream and to recover the organic components from theadsorbent. To ensure process efficiencies, it is important that all thehydrogen sulfide that is adsorbed from the feed gas must be recoveredand eventually converted to elemental sulfur. The process schemedepicted in FIG. 3 which illustrates an integrated process of naturalgas clean-up and contaminant removal from Claus feed streams, achievesthis purpose.

[0036] In FIG. 3, the process of this invention for removing organicsfrom a Claus feed stream is integrated with a process for removing polargases from natural gas. It is to be understood that the particularstream from which the hydrogen sulfide Claus feed stream originates isnot critical to this invention and can include natural gas and numerousrefinery gas streams which contain polar gases such as hydrogen sulfideand carbon dioxide. As shown in FIG. 3, a natural gas stream 1containing polar gases such as hydrogen sulfide and carbon dioxide ispassed to the bottom of an absorber 2. A lean amine solution from line 3flows down from top of absorber 2 counter-current to the flow of naturalgas stream 1 in absorber 2 and absorbs from the natural gas stream polargases such as hydrogen sulfide, carbon dioxide as well as heavyhydrocarbons which leave absorber 2 via line 4. Line 4 containing aminesolution, the absorbed polar gases and heavy hydrocarbons is nowdirected to near the top of an amine stripper 5 to separate the amineabsorbent from the contaminants which were absorbed from the natural gasstream. In amine stripper 5, the polar gases such as hydrogen sulfide,carbon dioxide and the heavy hydrocarbons are distilled from the aminesolution and are removed from the top of amine strippers via line 6. Theamine solution which is now essentially free of the absorbedcontaminants leaves the bottom of amine stripper 5 via line 7 and can berecycled to line 3 as a lean amine solution which can now absorb furthercontaminants from the natural gas stream by counter-current flow inamine absorber 2. The elevated temperature in amine stripper 5 can bemaintained by recycling part of the amine solution via line 7 toreboiler 8.

[0037] Stream 6 containing hydrogen sulfide, carbon dioxide, and otherhydrocarbons including heavy hydrocarbons forms the Claus reactor feedstream. As previously stated, the hydrocarbon contaminants pose aserious environmental problem with respect to converting the hydrogensulfide to sulphur via the Claus process. In accordance with the presentinvention, these hydrocarbon contaminants are now removed from the feedstream via adsorption which selectively removes the hydrocarbons fromthe hydrogen sulfide component. Importantly, the process of the presentinvention also solves the problem of hydrogen sulfide being co-adsorbedwith the hydrocarbons. These two aspects of the process of the presentinvention can now be described by again referring to FIG. 3.

[0038] Referring again to FIG. 3, a multiple thermal swing adsorption(TSA) system containing adsorbers 48 and 49 is described. A thirdadsorber (not shown) completes the process as will be later described.Alternatively, only two beds can be effectively used, in which case onebed is on adsorption while the other bed is being cooled or heated. Eachadsorber contains a bed of an adsorbent. Temperature conditions whichfollow are particularly useful when using EXS adsorbents. However, theprocess as described and depicted in FIG. 3 is useful for any of theadsorbents previously disclosed and equivalents thereof. Temperatureconditions may vary from the ranges set forth herein if other than EXSadsorbents are used. A process feed, for example, from amine stripper 5and typically containing 50-60 wt. % H₂S, 40-50% CO₂, 4% H₂O and 2%hydrocarbons is passed through adsorber 48 so as to remove thehydrocarbon content. In the process of this invention, distilled gasstream 6 becomes feed stream 52 which is heated to a temperature of atleast 50° C., and preferably from 60-100° C. in heater 53 and passed tothe bottom of the adsorber 48. Alternatively, although not shown in FIG.3, stream 6 may be cooled to a temperature of about 20° C. to removewater and the stream containing H₂S, CO₂, hydrocarbons and no more thanabout 1.5% H₂O, then heated to at least 50° C. The adsorption stepcontinues for about 1-5 hours. The product leaving the top of adsorber48 via line 54 is essentially free of the hydrocarbons and, if lowertemperatures within the described range are used, free of water. Afterthe adsorption step is stopped, the adsorber 48 is depressurizedco-currently to a pressure of 15 psia. In the depressurization step, thegas leaves the top of the adsorber 48 and no feed gas enters the bottomthereof.

[0039] After depressurization of the adsorber, the desorption processcan begin. The desorption process is depicted in conjunction withadsorber 49. In the desorption process, a fuel stream such as methanevia line 58 passes through a heater 60 which heats the methane to atemperature of at least 150° C., preferably between about 200-375° C.The heated methane via line 62 is used to regenerate the adsorbent bedin adsorber 49 by directing the methane via line 62 through the top ofthe adsorber 49 at a flow rate similar to the feed flow rate.Regeneration of the adsorbent bed typically lasts for a period of 1-5hours. At the conditions of temperature and flow rate, the adsorbedcomponents are desorbed from the adsorbent into the methane purge gas.The methane purge gas stream containing adsorbed hydrocarbons and minoramounts of coadsorbed hydrogen sulfide leave the bottom of adsorber 49via line 64. This purge stream containing the hydrocarbons and minoramounts of hydrogen sulfide is cooled in condenser 66 to a temperaturetypically at or below 100° C.

[0040] In accordance with this invention, the minor amounts of hydrogensulfide which have been coadsorbed with the hydrocarbons and now arecontained within the hydrocarbon stream desorbed from the adsorbent arerecovered. This recovery of the coadsorbed H₂S is believed novel andsolves a problem which has reduced process efficiencies as well asexacerbated environmental controls as previously described. Accordingly,after the purge gas stream has been cooled, it is directed via line 67to an absorption vessel 68 such as a static mixer. In absorption vessel68, the purge gas stream is mixed and contacted with a lean acid gasremoval solution which has been bled from line 7 to remove and separatethe H₂S from the purge gas stream. As shown in FIG. 3, the lean acid gasremoval solution is directed from stripper 5, via lines 7 and purge line70 to absorption vessel 68. As shown in the integrated process of FIG.3, the acid gas removal is achieved with amines which absorb essentiallyall of the hydrogen sulfide and carbon dioxide and other acid gases fromthe purge gas stream. It is understood that other acid gas solvents canbe used and that the use of amine solutions as herein described andindicated in the drawings include all such materials. Thus, lean acidgas removal solutions include alkanolamine solutions such as methyldiethanolamine, a physical solvent such as sulfolane, Selexol®,N-methylpyrolidone, a mixture of alkanolamine plus a physical solventsuch as sulfinol solution, an inorganic solvent such as potassiumcarbonate, an organic solvent such as propylene carbonate, an organicsolvent in combination with an alkanolamine or any other weak organiccompounds such as piperazine, or hydroxy ethyl piperazine. The preferredacid gas removal solution is an aqueous alkanolamine solution. The leanamine solution has only a minimum affinity for the desorbed hydrocarbonswhich are contained in the methane purge gas.

[0041] After the transfer of the hydrocarbon sulfide, carbon dioxide andother acid gases to the lean amine solution in absorption vessel 68 iscomplete, the purge gas stream along with the protonated acid gasremoval solution enter a two- or three-phase separation vessel where theprotonated solution is separated from the purge gas via densitydifferences. This is depicted in separation vessel 72. Depending uponthe operating conditions of separator 72 and the specific designthereof, the desorbed hydrocarbons could also be condensed and easilyseparated from the purge gas in this vessel. An optional cooler (notshown) can be placed between the absorption vessel 68 and the separationvessel 72 to enhance separation of the protonated solution from theheavier hydrocarbons and methane purge gas. An additional separator canbe used to remove the C₂+ hydrocarbons from the methane purge gas. Themethane purge gas via line 76 can be compressed and recycled back to thethermal swing adsorption unit as the purge gas via line 58. The aminesolution containing H₂S and CO₂ can be recycled from separator 72 vialine 74 to line 4 to strip the acid gases from the amine in stripper 5.

[0042] Following regeneration, the adsorbent bed must be repressurizedand cooled. Repressurization and cooling of the regenerated adsorbentbed is achieved by withdrawing product from adsorber 48 via line 54 andpassing the product through a third adsorber (not shown). In therepressurization step, the gas enters the top of adsorber and no gasleaves the bottom of the adsorber. In the cooling step, the gas againenters the top of the adsorber and leaves the bottom of the adsorber.Thus, the process of this invention lends itself to a three bed thermalswing adsorption system including continuous adsorption, desorption andrepressurization stages.

EXAMPLE 1

[0043] Heat of adsorption profiles for EXS sieves with chromatographicanalysis may serve as a convenient tool for adsorptive screening.Adsorptive assessment of CO₂ on a chromatographic column of desiccantgrade ETS-10 indicated a heat of adsorption of approximately 10.5Kcal/mole. Equivalent testing of propane indicated a heat of adsorptionof greater than 12 Kcal/mole. This indicates that propane could, inprinciple, be selectively adsorbed from a stream of CO₂. Propane waschosen as a test adsorbate because it is the smallest hydrocarbon ofconcern for Claus feed streams. Heats of adsorption forhydrocarbons/organics on ETS-10 rise with molecular size and thus themost difficult to remove by selective adsorption from a Claus gas feedstream would be propane.

[0044] In order to assess viability of propane (and by extension, largerhydrocarbons and organics) being stripped from a high CO₂ stream, a G.C.was set up with pure carbon dioxide as the carrier gas. With a flow of20 cc's per minute, CO₂ was passed through a 2½ gram bed (column) ofdesiccant grade ETS-10. A 5 cc sample of propane was injected at atemperature of 100° C. No elution of propane was observed for a periodof ½ hour. At that point, the temperature was raised to 200° C. Withthis temperature “swing”, the propane was rapidly eluted. Clearly, thisshowed the ability of ETS-10 to selectively adsorb small moleculeorganics from an acid gas stream.

EXAMPLE 2

[0045] A sample of partially hydrogen exchanged ETS-10 powder wassubjected to a series of single component isotherms at 100° C. Theadsorption isotherms are shown in FIG. 2. The isotherms demonstrate aselective adsorption of hydrocarbons relative to CO₂, H₂S and SO₂. Thehigher molecular weight hydrocarbons are more readily adsorbed than thelower molecular weight compounds.

EXAMPLE 3

[0046] A feed gas for a pilot plant was a synthetic mixture with thefollowing approximate compositions (by mole percent): Methane 0.1 Ethane0.1 Propane 0.1 Butane 0.2 Pentane 0.3 Hexane 0.35 Benzene 0.43 Toluene0.43 Water 4.0 Hydrogen Sulfide 47.0 Carbon Dioxide 47.0

[0047] The adsorber contained approximately 19.1 grams of Ca-H-ETS-10and could be operated at any reasonable temperature and pressure. Theflow of feed gas to the adsorber was 110 standard cubic centimeter perminute (SCCM) at a temperature of 60° C. and a pressure of 15.0 poundsper square inch gauge (PSIG). The outlet flow and composition of eachcomponent was measured to provide an adsorption time for each componentand a complete material balance. The adsorption time for each componentwas measured at a point in time where no further adsorption of thatcomponent was occurring. The adsorption times for each component are asfollows: Compound Minutes of Adsorption Carbon Dioxide 10 Methane <10Ethane 20 Hydrogen Sulfide 20 Propane 80 Butane 300 Pentane >400Hexane >400 Benzene >400

[0048] The results indicate that the ETS-10 adsorbent adsorbed and heldthe hydrocarbon within the adsorbent for times far exceeding those forthe acid gases CO₂ and H₂S. As shown, even propane could be continuallyadsorbed selectively from the acid gases.

EXAMPLE 4

[0049] A feed gas for a pilot plant was a synthetic mixture with thefollowing approximate compositions (by mole %) Methane 0.1% Ethane 0.1%Propane 0.1% Butane 0.2% Hexane 0.3% Benzene 0.43% Tolune 0.43% Water1.3% Hydrogen Sulfide 48% Carbon Dioxide 49%

[0050] The adsorber contained 20 grams of Y zeolite (HiSiv™ 1000) andwas operated at a temperature of 60° C. and a pressure of 15 psig. Theflow of feed gas to the adsorber was 110 SCCM. The outlet flow andcomposition of each component was measured to provide an adsorption timefor each component. The adsorption time for each component was measuredat a point in time corresponding to half its inlet concentration. Theadsorption times for each component are as follows: COMPOUNDBREAKTHROUGH TIME Methane Not Measured Ethane Not Measured Propane NotMeasured Butane  83 Hexane  329 Benzene >500 Tolune >500 Water NotMeasured Hydrogen Sulfide   9 Carbon Dioxide   9

[0051] The results indicated that the Y zeolite adsorbed the heavierhydrocarbons as well as ETS-10 while holding the H₂S to a lesser extent.However, the butane was not as strongly held. The high silica zeolite Ymaterial would be of value when heavy hydrocarbons (C6+) were the majorconcern.

EXAMPLE 5

[0052] The following process to remove hydrocarbons from a feed gas to aClaus plant depicts the multi-step adsorption process using threeadsorption beds as shown in FIG. 3 and described above. A bed of ETS-10is used as the adsorbent. During the adsorption step the feed gas is fedto the bottom of the adsorber. After three hours the adsorption step isstopped, and the bed is depressurized co-currently to 15 psia in aperiod of two minutes. After depressurization methane at a temperatureof 500° F. is used to regenerate the bed. Regeneration lasts for aperiod of three hours.

[0053] Following regeneration, the bed is repressurized to a pressure of30 psia with product gas leaving a bed that is undergoing the adsorptionstep. The repressurization step lasts for a period of two minutes. Therepressurized bed is further cooled with product gas leaving a bed thatis undergoing the adsorption step for a period of 175 minutes. Duringthe first 1½ minutes of the cooling step, the cooling gas is routedthrough a static mixer and contacted with a lean amine solution. Theresulting stream is passed to a three-phase separator. The gas streamleaving the three-phase separator during the first 1½ minutes of coolingis routed to the fuel system. For the subsequent 171 minutes of coolingall the gas leaving the adsorption bed is routed to the Claus furnace.

[0054] Compositions about the unit for the different steps are given inTable 1. Flow rates and step times are provided in Table 2. In bothTable 1 and Table 2, “bot” refers to bottom and “top” refers to top ofthe bed, respectively. Flow rates and compositions represent thecompositions (mol %) entering or leaving the bed. In the adsorptionstep, gas enters the bottom of the bed and leaves the top of the bed. Inthe depressurization step, gas leaves the top of the bed and no gasenters the bed. In the heating step, gas enters the top of the bed andleaves the bottom of the bed. In the repressurization step, gas entersthe top of the bed and no gas leaves the bed. In the cooling step, gasenters the top of the bed and leaves the bottom of the bed. TABLE 1Pentane Butane H₂S CO₂ Methane Adsorb Top 0.0001 0.0017 49.7956 50.20220.0004 Adsorb Bot 0.7 0.3 49 49.9999 0.0001 Depressurize Top 0 0.011850.7393 49.2491 0.0002 Depressurize Bot 0 0 0 0 0 Heat 0 to 20 Top0.0001 0.0001 0.0001 0.0001 99.9996 min. Heat 0 to 20 Bot 0.3338 0.133817.9015 11.8192 69.8117 min. Heat 20 to Top 0.0001 0.0001 0.0001 0.000199.9996 40 min. Heat 20 to Bot 0.155 0.0533 5.5814 0.3776 93.8327 40min. Heat 40 to Top 0.0001 0.0001 0.0001 0.0001 99.9996 60 min. Heat 40to Bot 0.1022 0.0304 2.8151 0.0024 97.0499 60 min. Heat 60 to Top 0.00010.0001 0.0001 0.0001 99.9996 80 min. Heat 60 to Bot 0.0706 0.0185 1.33130.0002 98.5793 80 min. Heat 80 to Top 0.0001 0.0001 0.0001 0.000199.9996 100 min. Heat 80 to Bot 0.3105 0.6109 0.2063 0.0001 98.8721 100min. Heat 100 to Top 0.0001 0.0001 0.0001 0.0001 99.9996 120 min. Heat100 to Bot 1.301 2.1762 0.0001 0.0001 96.5225 120 min. Heat 120 to Top0.0001 0.0001 0.0001 0.0001 99.9996 140 min. Heat 120 to Bot 3.28410.0007 0.0001 0.0001 96.7149 140 min. Heat 140 to Top 0.0001 0.00010.0001 0.0001 99.9996 160 min. Heat 140 to Bot 1.5256 0.0001 0.00010.0001 98.4741 160 min. Heat 160 to Top 0.0001 0.0001 0.0001 0.000199.9996 180 min. Heat 160 to Bot 0.0004 0.0001 0.0001 0.0001 99.9993 180min. Repressurize Top 0 0 50 50 0 Repressurize Bot 0 0 0 0 0 Cool 0-1.5Top 0 0 50 50 0 min. Cool 0-1.5 Bot 0.0004 0.0003 0.0049 26.9787 73.0156min. Cool 1.5- Top 0.0001 0.0017 49.7956 50.2022 0.0004 174.5 min. Cool1.5- Bot 0 0.0001 48.5824 51.4171 0.0004 174.5 min.

[0055] TABLE 2 Time Flow (MMSCFD) (min.) Adsorb Top 7.76 180 Adsorb Bot7.70 Depressurize Top 4.24 2 Depressurize Bot 0.00 Heat 0 to 20 Top 6.5420 min. Heat 0 to 20 Bot 8.82 min. Heat 20 to 40 Top 6.54 20 min. Heat20 to 40 Bot 7.01 min. Heat 40 to 60 Top 6.54 20 min. Heat 40 to 60 Bot6.84 min. Heat 60 to 80 Top 6.54 20 min. Heat 60 to 30 Bot 6.76 min.Heat 80 to Top 6.54 20 100 min. Heat 80 to Bot 6.70 100 min. Heat 100 toTop 6.54 20 120 min. Heat 100 to Bot 6.79 120 min. Heat 120 to Top 6.5420 140 min. Heat 120 to Bot 6.77 140 min. Heat 140 to Top 6.54 20 160min. Heat 140 to Bot 6.65 160 min. Heat 160 to Top 6.54 20 180 min. Heat160 to Bot 6.55 180 min. Repressurize Top 5.43 2 Repressurize Bot 0.00Cool H₂S CO₂ Top 7.32 1.5 Cool H₂S CO₂ Bot 0.97 Cool H₂S CO₂ Top 7.17174.5 Cool H₂S CO₂ Bot 7.56

[0056] Once given the above disclosure, many other features,modifications, and improvements will become apparent to the skilledartisan. Such other features, modifications, and improvements are,therefore, considered to be a part of this invention, the scope of whichis to be determined by the following claims.

We claim:
 1. A process for the removal of hydrocarbons from a mixture ofthe same with acid gases which comprises; contacting said mixture with atitanium silicate molecular sieve containing octahedrally coordinatedtitania chains connected by tetrahedral silica, whereby the hydrocarbonsare preferentially removed from the mixture.
 2. The process of claim 1,wherein said acid gases comprise hydrogen sulfide, carbon dioxide ormixtures thereof.
 3. The process of claim 1, wherein said mixture iscontacted with said molecular sieve at a temperature of at least 50° C.4. The process of claim 3, wherein said mixture is contacted with saidmolecular sieve at a temperature of from about 60-100° C.
 5. The processof claim 1, wherein said acid gas stream further includes water.
 6. Theprocess of claim 5, wherein said mixture is contacted with saidmolecular sieve at a temperature of at least 50° C., but less than 100°C.
 7. The process of claim 1, wherein said titanium silicate molecularsieve is selected from the group consisting of ETS-4, ETS-10, ETAS-10and cation-exchanged versions thereof.
 8. The process of claim 7,wherein said molecular sieve is ETS-10 or cation-exchanged versionsthereof.
 9. The process of claim 1, wherein subsequent to contactingsaid mixture with the molecular sieve, the molecular sieve is treated soas to provide desorption of the hydrocarbons therefrom.
 10. The processof claim 9, wherein the desorption is provided by changing thetemperature of the molecular sieve.
 11. The process of claim 10, whereinthe mixture is contacted with said molecular sieve to adsorbhydrocarbons from said acid gases at a temperature of from about 50-100°C. and subsequently, the temperature of said molecular sieve is elevatedto at least 150 EC. to provide said desportion.
 12. The process of claim10, wherein desorption of the hydrocarbons from the molecular sieve isfurther provided by contacting the molecular sieve after adsorption ofthe hydrocarbons with a purge gas.
 13. The process of claim 12, whereinsaid purge gas is methane.
 14. In a process for feeding a hydrogensulfide-containing gas stream to a Claus process and converting thehydrogen sulfide to elemental sulfur and wherein the feed stream to theClaus process comprises hydrogen sulfide and minor amounts ofhydrocarbons and other organic contaminants, the improvement whichcomprises: passing the said feed stream in contact with a titaniumsilicate molecular sieve containing octahedrally coordinated titaniachains linked by tetrahedral silica to thereby selectively adsorb thehydrocarbons and other organics from the feed stream and passing thetreated feed stream having reduced hydrocarbon and other organics to theClaus process.
 15. The improvement of claim 14, wherein said feed streamis contacted with said molecular sieve at a temperature of from about50-100° C.
 16. The process of claim 14, wherein said titanium silicatemolecular sieve is selected from the group consisting of ETS-4, ETS-10,ETAS-10 and cation-exchanged versions and mixtures thereof.
 17. Theprocess of claim 15, wherein said molecular sieve, after having adsorbedthe hydrocarbons and other organics from said feed stream, isregenerated by desorption of the hydrocarbons and other organics fromsaid molecular sieve by a temperature swing.
 18. The process of claim17, wherein during said desorption, the temperature of the molecularsieve is raised to at least 150° C.
 19. The process of claim 18, whereinsaid desorption is further provided by passing a purge stream intocontact with said molecular sieve which contains adsorbed hydrocarbonsand other organics.
 20. The process of claim 19, wherein said purgestream, after contacting said molecular sieve to provide desorption ofhydrocarbons and other organics therefrom and into said purge streams,is contacted with a lean acid gas removal solution to remove anyhydrogen sulfide which has been adsorbed by said molecular sieve fromsaid feed gas, and which is desorbed into said purge stream.
 21. Theprocess of claim 20, wherein the mixture of said purge stream and saidacid gas removal solution is cooled to separate the acid gas removalsolution containing hydrogen sulfide from the purged gas containing saidhydrocarbons and other organic compounds.
 22. The process of claim 14,wherein said feed stream is a natural gas stream.
 23. The process ofclaim 14, wherein said feed stream is a gas stream from refineryprocessing.
 24. A process for the removal of hydrocarbons from a mixtureof the same with acid gases which comprises: contacting said mixturewith an adsorbent which selectively removes hydrocarbons from saidmixture, recovering a gas stream passing through said adsorbent whichhas a reduced hydrocarbon content, subsequently treating said adsorbentto provide desorption of a hydrocarbon stream from said adsorbent, saidhydrocarbon stream containing minor amounts of acid gases which havebeen coadsorbed from said mixture, and contacting said hydrocarbonstream with a lean acid gas removal solution to remove at least aportion of the minor amounts of acid gases which are contained withinsaid hydrocarbon stream.
 25. The process of claim 24, wherein said acidgases include hydrogen sulfide.
 26. The method of claim 25, wherein saidlean acid gas removal solution comprises one or more amines.
 27. Themethod of claim 24, wherein said adsorbent is treated to providedesorption of said hydrocarbon stream by raising the temperature of saidadsorbent.
 28. The method of claim 27, wherein said adsorbent is treatedto provide desorption of said hydrocarbon stream by further passing ahydrocarbon purge stream through said adsorbent.
 29. The process ofclaim 24, wherein said mixture of acid gases and hydrocarbons isobtained by contacting a process gas stream with an acid gas removalsolution which removes from said process gas, acid gases and minoramounts of hydrocarbons to form an initial mixture, separating saidinitial mixture into said mixture of hydrocarbons and acid gases and aseparate lean acid gas removal solution stream which contains reducedlevels of acid gases.
 30. The process of claim 29, wherein said separatelean acid gas removal solution stream is contacted with said desorbedhydrocarbon stream to remove said portion of acid gases from saidhydrocarbon stream.
 31. The process of claim 30, wherein said acid gasremoval solution is an amine solution.
 32. The process of claim 30,wherein subsequent to contacting said desorbed hydrocarbon stream withsaid separate lean acid gas removal solution stream, the desorbedhydrocarbon stream is separated into a hydrocarbon stream and a richacid gas removal solution which contains acid gases.
 33. The process ofclaim 32, wherein said rich acid gas removal solution is combined withsaid initial mixture of acid gases and hydrocarbons.
 34. The process ofclaim 24, wherein said process gas stream is natural gas.
 35. Theprocess of claim 24, wherein said process gas stream is from a refineryprocess.
 36. The process of claim 24, wherein said adsorbent is atitanium silicate containing octahedrally coordinated titania chainslinked by tetrahedrally coordinated silica.
 37. The process of claim 36,wherein said adsorbent is ETS-10.
 38. The process of claim 24, whereinsaid adsorbent is a high silica aluminosilicate zeolite.
 39. The processof claim 38, wherein said zeolite has a SiO₂/A₂O₃ mole ratio of at least4.
 40. A process for the removal of hydrocarbons from a mixture of thesame with acid gases which comprises; contacting said mixture with aaluminosilicate zeolite molecular sieve having a silica to alumina ratioof at least 4, whereby the hydrocarbons are preferentially removed fromthe mixture.
 41. The process of claim 40, wherein said silica to aluminoratio is at least
 5. 42. The process of claim 40, wherein said adsorbentis zeolite Y.
 43. The process of claim 40, wherein said acid gasescomprise hydrogen sulfide, carbon dioxide or mixtures thereof.
 44. Theprocess of claim 40, wherein subsequent to contacting said mixture withthe molecular sieve, the molecular sieve is treated so as to providedesorption of the hydrocarbons therefrom.
 45. The process of claim 44,wherein the desorption is provided by changing the temperature of themolecular sieve.
 46. In a process for feeding a hydrogensulfide-containing gas stream to a Claus process and converting thehydrogen sulfide to elemental sulfur and wherein the feed stream to theClaus process comprises hydrogen sulfide and minor amounts ofhydrocarbons and other organic contaminants, the improvement whichcomprises: passing the said feed stream in contact with aaluminosilicate zeolite having a silica to alumina mole ratio of atleast 4 to thereby selectively adsorb the hydrocarbons and otherorganics from the feed stream and passing the treated feed stream havingreduced hydrocarbon and other organics to the Claus process.
 47. Theprocess of claim 46, wherein said molecular sieve, after having adsorbedthe hydrocarbons and other organics from said feed stream, isregenerated by desorption of the hydrocarbons and other organics fromsaid molecular sieve by a temperature swing.
 48. The process of claim47, wherein said desorption is further provided by passing a purgestream into contact with said molecular sieve which contains adsorbedhydrocarbons and other organics.
 49. The process of claim 48, whereinsaid purge stream, after contacting said molecular sieve to providedesorption of hydrocarbons and other organics therefrom and into saidpurge stream, is contacted with a lean acid gas removal solution toremove any hydrogen sulfide which has been adsorbed by said molecularsieve from said feed gas, and which is desorbed into said purge stream.50. The process of claim 46, wherein said feed stream is a natural gasstream.